U.S. patent application number 13/942024 was filed with the patent office on 2015-01-15 for downhole construction of vacuum insulated tubing.
This patent application is currently assigned to Chevron U.S.A. Inc.. The applicant listed for this patent is George Taylor Armistead. Invention is credited to George Taylor Armistead.
Application Number | 20150013993 13/942024 |
Document ID | / |
Family ID | 51261275 |
Filed Date | 2015-01-15 |
United States Patent
Application |
20150013993 |
Kind Code |
A1 |
Armistead; George Taylor |
January 15, 2015 |
DOWNHOLE CONSTRUCTION OF VACUUM INSULATED TUBING
Abstract
A method for adjusting a pressure within a wellbore. The method
can include inserting a first tubing into the wellbore. The method
can also include mechanically coupling a bottom coupling feature of
a multiple connection bushing to the first tubing. The method can
further include mechanically coupling a second tubing to a first
top coupling feature of the multiple connection bushing. The method
can also include mechanically coupling a third tubing to a second
top coupling feature of the multiple connection bushing, where the
third tubing has an inner diameter that is greater than an outer
diameter of the second tubing. The method can further include
inserting the multiple connection bushing, the second tubing and
the third tubing into the wellbore. The method can also include
adjusting the pressure within a space between the second tubing,
the third tubing, and the multiple connection bushing.
Inventors: |
Armistead; George Taylor;
(Katy, TX) |
|
Applicant: |
Name |
City |
State |
Country |
Type |
Armistead; George Taylor |
Katy |
TX |
US |
|
|
Assignee: |
Chevron U.S.A. Inc.
San Ramon
CA
|
Family ID: |
51261275 |
Appl. No.: |
13/942024 |
Filed: |
July 15, 2013 |
Current U.S.
Class: |
166/381 ;
166/67 |
Current CPC
Class: |
E21B 36/00 20130101;
E21B 17/18 20130101; E21B 17/04 20130101; E21B 23/01 20130101; E21B
36/003 20130101 |
Class at
Publication: |
166/381 ;
166/67 |
International
Class: |
E21B 43/18 20060101
E21B043/18 |
Claims
1. A method for adjusting a pressure within a wellbore, the method
comprising: inserting a first tubing into the wellbore;
mechanically coupling a bottom coupling feature of a multiple
connection bushing to the first tubing, wherein the multiple
connection bushing further comprises a first top coupling feature
and a second top coupling feature; mechanically coupling a second
tubing to the first top coupling feature of the multiple connection
bushing; mechanically coupling a third tubing to the second top
coupling feature of the multiple connection bushing, wherein the
third tubing has an inner diameter that is greater than an outer
diameter of the second tubing; inserting the multiple connection
bushing, the second tubing, and the third tubing into the wellbore;
and adjusting the pressure within a space between the second
tubing, the third tubing, and the multiple connection bushing.
2. The method of claim 1, further comprising: positioning, after
mechanically coupling a second tubing to the first top coupling
feature of the multiple connection bushing, at least one
centralizer around an outer surface of the second tubing.
3. The method of claim 1, wherein the third tubing has an outer
diameter that is less than an inner diameter of a production tubing
inserted into the wellbore.
4. The method of claim 1, wherein the second tubing comprises a
plurality of second tubing members that are mechanically coupled to
each other on an end-to-end basis, and wherein the third tubing
comprises a plurality of third tubing members that are mechanically
coupled to each other on an end-to-end basis.
5. The method of claim 4, wherein a second tubing member of the
plurality of second tubing members is mechanically coupled to the
first top coupling feature of the multiple connection bushing
before a third tubing member of the plurality of third tubing
members is mechanically coupled to the second top coupling feature
of the multiple connection bushing.
6. The method of claim 5, wherein, after inserting the multiple
connection bushing, the second tubing member and the third tubing
member into the wellbore, another second tubing member of the
plurality of second tubing members is mechanically coupled to the
second tubing member before another third tubing member is
mechanically coupled to the third tubing member.
7. The method of claim 1, further comprising: allowing the second
tubing to expand and contract with temperature independent of
expansion and contraction of the third tubing.
8. The method of claim 7, wherein the pressure is maintained within
the space when the second tubing expands and contracts.
9. The method of claim 1, wherein the working fluid comprises an
injection pressure of approximately 3,300 pounds per square inch,
wherein the working fluid is injected into an annulus of the first
tubing.
10. The method of claim 1, wherein the pressure within the space is
adjusted toward zero, and wherein the pressure within the space is
substantially uniform along its length.
11. A method for extracting a downhole fluid in a wellbore using
vacuum-insulated tubing, the method comprising: inserting first
tubing into the wellbore; mechanically coupling a bottom coupling
feature of a multiple connection bushing to the first tubing,
wherein the multiple connection bushing further comprises a first
top coupling feature and a second top coupling feature;
mechanically coupling a second tubing to the first top coupling
feature of the multiple connection bushing; mechanically coupling a
third tubing to the second top coupling feature of the multiple
connection bushing, wherein the third tubing has an inner diameter
that is greater than an outer diameter of the second tubing;
inserting the multiple connection bushing, the second tubing, and
the third tubing into the wellbore; adjusting a pressure within a
space between the second tubing, the third tubing, and the multiple
connection bushing; inserting a working fluid into a cavity formed
by an annulus of the first tubing, a passage through the multiple
connection bushing, and an annulus of the second tubing; and
extracting, using completion equipment, production fluid after the
working fluid interacts with the production fluid.
12. The method of claim 11, wherein the pressure within the space
is adjusted toward zero, and wherein the second tubing has a first
temperature that is substantially higher than a second temperature
of the third tubing when the working fluid is inserted into the
cavity.
13. The method of claim 11, wherein the working fluid has a
temperature that exceeds 750.degree. F.
14. A system for adjusting a pressure within a wellbore, the system
comprising: a first tubing disposed within the casing and
comprising an open distal end and a proximal end; a multiple
connection bushing mechanically coupled to the proximal end of the
first tubing using a bottom coupling feature, wherein the multiple
connection bushing further comprises a first top coupling feature
and a second top coupling feature; a second tubing disposed within
the casing and mechanically coupled to the first top coupling
feature of the multiple connection bushing; a third tubing disposed
within the casing and mechanically coupled to the second top
coupling feature of the multiple connection bushing, wherein the
third tubing has an inner diameter that is greater than an outer
diameter of the second tubing; and a vacuum system located
proximate to a surface and communicably coupled to a space between
the second tubing and the third tubing, wherein the vacuum system
adjusts a pressure within the space.
15. The system of claim 14, further comprising: a power source
located proximate to the surface; an injection device electrically
coupled to the power source, wherein the injection device is
located proximate to the surface, and wherein the injection device
is communicably coupled to, and sends a working fluid down, a first
cavity formed by an annulus of the second tubing, a passage through
the multiple connection bushing, and an annulus of the first
tubing; and completion equipment electrically coupled to the power
source and disposed in the wellbore below the first tubing.
16. The system of claim 15, further comprising: a casing disposed
within the wellbore and comprising a plurality of perforations for
receiving the production fluid from a reservoir adjacent to the
plurality of perforations, wherein the third tubing has an outer
diameter that is less than an inner diameter of the casing, and a
cable mechanically coupled to the power source and the completion
equipment, wherein the cable is disposed between the casing and the
third tubing.
17. The system of claim 14, further comprising: at least one
centralizer disposed between the second tubing and the third
tubing, wherein the at least one centralizer is made of a thermally
non-conductive material.
18. The system of claim 14, further comprising: a riser housing
positioned atop a wellhead spool above the surface; and a riser
joint mechanically coupled to a proximal end of the second tubing,
wherein the riser joint is moveably coupled to, and positioned
inside of a channel that traverses, the riser housing.
19. The system of claim 18, further comprising: a lubricant
disposed within a second cavity formed between the riser housing
and the riser joint; and at least one sealing member disposed
within a wall of the riser housing between the riser housing and
the riser joint.
20. The system of claim 14, wherein the vacuum system comprises a
vacuum pump.
Description
TECHNICAL FIELD
[0001] The present application relates to adjusting pressure within
a wellbore, and in particular, methods and systems of adjusting
pressure using tubing downhole in a subterranean wellbore.
BACKGROUND
[0002] Heavy oil and tar sands comprise significant existing
resources for liquid hydrocarbons to the extent that they can be
economically produced. Generally, heavy oil from tar sand and
bitumen deposits must be heated to reduce the oil or mineral
viscosity before it will flow, or to enhance flow, into producing
wells. The predominant method for heating utilized in the field is
the injection of a hot fluid or gas (generally referred to herein
as a "working fluid"), usually steam, from the surface, although
electrical heating is also practiced. However, as the working fluid
passes through production tubing, heat is generally lost to the
surrounding rock based on the thermal conductivity of the exterior
of the production tubing system.
[0003] Generally, vacuum insulated tubing having a relatively low
heat conductance value can be utilized as a thermal insulator for
minimizing heat loss from the working fluid into the surrounding
rock. Conventional vacuum insulated tubing is manufactured by
incorporating a tubing sheath or segment on an exterior of a joint
of tubing, welding at each end of the tubing near a connection to
create a seal, and then drawing a vacuum between the two pipe
segments. This conventional method of constructing vacuum-insulated
tubing can be expensive, however, and does not provide insulation
at the connection areas. Therefore, heat loss from the working
fluid into the surrounding rock may be realized between each
segment of the vacuum insulated tubing. If too much thermal energy
is conducted from one side of the vacuum to the other through the
poorly insulated connection areas, damage can occur to the
formation.
SUMMARY
[0004] In general, in one aspect, the disclosure relates to a
method for adjusting a pressure within a wellbore. The method can
include inserting a first tubing into the wellbore, and
mechanically coupling a bottom coupling feature of a multiple
connection bushing to the first tubing, where the multiple
connection bushing further includes a first top coupling feature
and a second top coupling feature. The method can also include
mechanically coupling a second tubing to the first top coupling
feature of the multiple connection bushing, and mechanically
coupling a third tubing to the second top coupling feature of the
multiple connection bushing, where the third tubing has an inner
diameter that is greater than an outer diameter of the second
tubing. The method can further include inserting the multiple
connection bushing, the second tubing, and the third tubing into
the wellbore, and adjusting the pressure within a space between the
second tubing, the third tubing, and the multiple connection
bushing.
[0005] In general, in one aspect, the disclosure relates to a
method for extracting a downhole fluid in a wellbore using
vacuum-insulated tubing. The method can include inserting first
tubing into the wellbore, and mechanically coupling a bottom
coupling feature of a multiple connection bushing to the first
tubing, where the multiple connection bushing further comprises a
first top coupling feature and a second top coupling feature. The
method can also include mechanically coupling a second tubing to
the first top coupling feature of the multiple connection bushing,
and mechanically coupling a third tubing to the second top coupling
feature of the multiple connection bushing, where the third tubing
has an inner diameter that is greater than an outer diameter of the
second tubing. The method can further include inserting the
multiple connection bushing, the second tubing, and the third
tubing into the wellbore, and adjusting a pressure within a space
between the second tubing, the third tubing, and the multiple
connection bushing. The method can also include inserting a working
fluid into a cavity formed by an annulus of the first tubing, a
passage through the multiple connection bushing, and an annulus of
the second tubing. The method can further include extracting, using
completion equipment, production fluid after the working fluid
interacts with the production fluid.
[0006] In another aspect, the disclosure can generally relate to a
system for adjusting a pressure within a wellbore. The system can
include a first tubing disposed within the casing and having an
open distal end and a proximal end. The system can also include a
multiple connection bushing mechanically coupled to the proximal
end of the first tubing using a bottom coupling feature, where the
multiple connection bushing further includes a first top coupling
feature and a second top coupling feature. The system can further
include a second tubing disposed within the casing and mechanically
coupled to the first top coupling feature of the multiple
connection bushing. The system can also include a third tubing
disposed within the casing and mechanically coupled to the second
top coupling feature of the multiple connection bushing, where the
third tubing has an inner diameter that is greater than an outer
diameter of the second tubing. The system can further include a
vacuum system located proximate to a surface and communicably
coupled to a space between the second tubing and the third tubing,
where the vacuum system adjusts the pressure within the space.
[0007] These and other aspects, objects, features, and embodiments
will be apparent from the following description and the appended
claims.
BRIEF DESCRIPTION OF THE DRAWINGS
[0008] The drawings illustrate only example embodiments of methods,
systems, and devices for creating vacuum-insulated tubing in a
wellbore (also called herein a "borehole") and are therefore not to
be considered limiting of its scope, as creating vacuum-insulated
tubing in a wellbore may admit to other equally effective
embodiments. The elements and features shown in the drawings are
not necessarily to scale, emphasis instead being placed upon
clearly illustrating the principles of the example embodiments.
Additionally, certain dimensions or positionings may be exaggerated
to help visually convey such principles. In the drawings, reference
numerals designate like or corresponding, but not necessarily
identical, elements. Designations such as "first", "second", and
"third" are merely used to show a different feature. Descriptions
such as "top", "bottom", "distal", and "proximal" are meant to
describe different portions of an element or component and are not
meant to imply an absolute orientation.
[0009] FIG. 1 shows a schematic diagram of a field system in which
vacuum-insulated tubing can be created in a wellbore in accordance
with certain example embodiments.
[0010] FIG. 2 shows a schematic diagram of a system for adjusting a
pressure within a wellbore in accordance with certain example
embodiments.
[0011] FIG. 3 shows a schematic diagram of another system for
adjusting a pressure within a wellbore in accordance with certain
example embodiments.
[0012] FIG. 4 shows a flowchart presenting a method for adjusting a
pressure within a wellbore in accordance with certain example
embodiments.
[0013] FIG. 5 shows a flowchart presenting a method for extracting
a downhole fluid in a wellbore using vacuum-insulated tubing in
accordance with certain example embodiments.
DETAILED DESCRIPTION OF EXAMPLE EMBODIMENTS
[0014] Example embodiments directed to vacuum-insulated tubing in a
wellbore will now be described in detail with reference to the
accompanying figures. Like, but not necessarily the same or
identical, elements in the various figures are denoted by like
reference numerals for consistency. In the following detailed
description of the example embodiments, numerous specific details
are set forth in order to provide a more thorough understanding of
the disclosure herein. However, it will be apparent to one of
ordinary skill in the art that the example embodiments herein may
be practiced without these specific details. In other instances,
well-known features have not been described in detail to avoid
unnecessarily complicating the description. As used herein, a
length, a width, and a height can each generally be described as
lateral directions.
[0015] In certain example embodiments, production fluid as
described herein is one or more of any solid, liquid, and/or vapor
that can be found in a subterranean formation. Examples of a
production fluid can include, but are not limited to, crude oil,
natural gas, water, steam, and hydrogen gas. Production fluid can
be called other names, including but not limited to downhole fluid,
reservoir fluid, a resource, and a field resource.
[0016] A user as described herein may be any person that is
involved with extracting and/or controlling one or more production
fluids in a wellbore of a subterranean formation of a field.
Examples of a user may include, but are not limited to, a company
representative, a drilling engineer, a tool pusher, a service hand,
a field engineer, an electrician, a mechanic, an operator, a
consultant, a contractor, a roughneck, and a manufacturer's
representative.
[0017] As used herein a working fluid can be used to describe any
liquid or vapor that has a temperature that is higher (in some
cases, significantly higher) than the temperature of a production
fluid in a wellbore. The working fluid can be sent into the
wellbore and transfer heat to the production fluid in the wellbore.
By heating the production fluid, the production fluid can be
extracted from the wellbore more easily because the viscosity
increases. An example of a working fluid is high-temperature
steam.
[0018] FIG. 1 shows a schematic diagram of a field system 100 in
which vacuum-insulated tubing can be created and used in a
subterranean wellbore in accordance with one or more example
embodiments. In one or more embodiments, one or more of the
features shown in FIG. 1 may be omitted, added, repeated, and/or
substituted. Accordingly, embodiments of a field system should not
be considered limited to the specific arrangements of components
shown in FIG. 1.
[0019] Referring now to FIG. 1, the field system 100 in this
example includes a wellbore 120 that is formed in a subterranean
formation 110 using field equipment 130 above a surface 102, such
as ground level for an on-shore application and the sea floor for
an off-shore application. The point where the wellbore 120 begins
at the surface 102 can be called the entry point. The subterranean
formation 110 can include one or more of a number of formation
types, including but not limited to shale, limestone, sandstone,
clay, sand, and salt. In certain embodiments, a subterranean
formation 110 can also include one or more reservoirs in which one
or more resources (e.g., oil, gas, water, steam) can be located.
One or more of a number of field operations (e.g., drilling,
setting casing, extracting production fluids) can be performed to
reach an objective of a user with respect to the subterranean
formation 110.
[0020] The wellbore 120 can have one or more of a number of
segments, where each segment can have one or more of a number of
dimensions. Examples of such dimensions can include, but are not
limited to, a size (e.g., diameter) of the wellbore 120, a
curvature of the wellbore 120, a total vertical depth of the
wellbore 120, a measured depth of the wellbore 120, and a
horizontal displacement of the wellbore 120. The field equipment
130 can be used to create and/or develop (e.g., create a vacuum
within, insert a working fluid into, extract production fluids
from) the wellbore 120. The field equipment 130 can be positioned
and/or assembled at the surface 102. The field equipment 130 can
include, but is not limited to, a derrick, a tool pusher, a clamp,
a tong, drill pipe, a drill bit, a vacuum system, an injection
device, completion equipment, a riser housing, a riser joint,
centralizers, tubing pipe (also simply called tubing), a power
source, a packer, and casing pipe (also simply called casing).
[0021] The field equipment 130 can also include one or more devices
that measure and/or control various aspects (e.g., direction of
wellbore 120, pressure, temperature) of a field operation
associated with the wellbore 120. For example, the field equipment
130 can include a wireline tool that is run through the wellbore
120 to provide detailed information (e.g., curvature, azimuth,
inclination) throughout the wellbore 120. Such information can be
used for one or more of a number of purposes. For example, such
information can dictate the size (e.g., outer diameter) of a casing
pipe to be inserted at a certain depth in the wellbore 120.
[0022] FIG. 2 shows a schematic diagram of a system 200 for
vacuum-insulated tubing in a wellbore in accordance with certain
example embodiments. In one or more embodiments, one or more of the
features shown in FIG. 2 may be omitted, added, repeated, and/or
substituted. Accordingly, embodiments of a system for
vacuum-insulated tubing should not be considered limited to the
specific arrangements of components shown in FIG. 2.
[0023] The system 200 of FIG. 2 can include casing 260, a number of
different tubing (e.g., tubing 210, tubing 215, tubing 220), a
multiple connection bushing 230, a number of centralizers 250, a
number of wellhead spools (e.g., lower wellhead spool 270, spacer
wellhead spool 280, upper wellhead spool 290), a Christmas tree
295, a vacuum system 285, an injection device 207, a power source
203, completion equipment 297, and one or more power cables 299.
Referring to FIGS. 1 and 2, the casing 260 can include a number of
casing pipes that are mechanically coupled to each other
end-to-end, usually with mating threads. The casing pipes of the
casing 260 can be mechanically coupled to each other directly or
using a coupling device, such as a coupling sleeve.
[0024] Each casing pipe of the casing 260 can have a length and a
width (e.g., outer diameter). The length of a casing pipe can vary.
For example, a common length of a casing pipe is approximately 40
feet. The length of a casing pipe can be longer (e.g., 60 feet) or
shorter (e.g., 10 feet) than 40 feet. The width of a casing pipe
can also vary and can depend on the cross-sectional shape of the
casing pipe. For example, when the cross-sectional shape of the
casing pipe is circular, the width can refer to an outer diameter,
an inner diameter, or some other form of measurement of the casing
pipe. Examples of a width in terms of an outer diameter can
include, but are not limited to, 7 inches, 75/8 inches, 85/8
inches, 103/4 inches, 133/8 inches, and 14 inches.
[0025] The size (e.g., width, length) of the casing 260 is
determined based on the information gathered using field equipment
130 with respect to the wellbore 120 in the subterranean formation
110. The walls of the casing 260 have an inner surface that forms a
cavity 208 that traverses the length of the casing 260. The casing
260 can be made of one or more of a number of suitable materials,
including but not limited to steel. In certain example embodiments,
the casing 260 is set along substantially all of the length of the
wellbore 120. In order to extract production fluid from the
reservoir in the formation 110, one or more of a number of
perforations can be made in the casing 260. Such perforations allow
the production fluid to enter the cavity 208 from a reservoir in
the formation 110 adjacent to the perforations. The perforations
can be made using one or more of a number of perforating
technologies currently used or to be discovered with respect to a
field operation.
[0026] The tubing (e.g., tubing 210, tubing 215, tubing 220)
(sometimes called a tubing string) can include a number of tubing
pipes (also called tubing pipe members) that are mechanically
coupled to each other end-to-end, usually with mating threads. The
tubing pipes of a tubing string can be mechanically coupled to each
other directly or using a coupling device, such as a coupling
sleeve. As in this case, more than one tubing string can be
disposed within a cavity 208 of the casing 260.
[0027] Each tubing pipe of a tubing string can have a length and a
width (e.g., outer diameter). The length of a tubing pipe can vary.
For example, a common length of a tubing pipe is approximately 30
feet. The length of a tubing pipe can be longer (e.g., 40 feet) or
shorter (e.g., 10 feet) than 30 feet. The width of a tubing pipe
can also vary and can depend on one or more of a number of factors,
including but not limited to the inner diameter of the casing pipe.
For example, the width of the tubing pipe is less than the inner
diameter of the casing pipe. The width of a tubing pipe can refer
to an outer diameter, an inner diameter, or some other form of
measurement of the tubing pipe. Examples of a width in terms of an
outer diameter can include, but are not limited to, 7 inches, 5
inches, and 4 inches.
[0028] The distal end of the tubing 215 can be located toward the
bottom of the wellbore 120, and the proximal end of the tubing 215
can be located closer to the surface 102. In certain example
embodiments, the distal end of the tubing 215 is open
(substantially unobstructed) and is positioned within the cavity
208 of the wellbore 120. In such a case, the casing 260 can extend
further into the wellbore 120 than the tubing (in this case, tubing
215).
[0029] The size (e.g., outer diameter, length) of the tubing can be
determined based, in part, on the size of the cavity 208 within the
casing 260 and/or the configuration of the multiple connection
bushing 230. The walls of the tubing have an inner surface that
each forms a cavity. For example, the inner surface 212 of tubing
210 forms a cavity 216 (also called an annulus 216) that traverses
the length of the tubing 210, and the inner surface of tubing 215
forms a cavity 217 (also called an annulus 217) that traverses the
length of the tubing 215. The tubing can be made of one or more of
a number of suitable materials, including but not limited to steel.
The one or more materials of the tubing can be the same or
different than the materials of the casing 260.
[0030] In certain example embodiments, the size of the tubing 220
is larger than the size of the tubing 210. For example, the tubing
220 can have an inner diameter (defined by inner surface 222) that
is larger than the outer diameter (defined by outer surface 214) of
the tubing 210. As a specific example, the tubing 210 can have an
inner diameter of 3.5 inches and an outer diameter of 3.961 inches,
while the tubing 220 can have an inner diameter of 4.611 inches and
an outer diameter of 5.5 inches. In such a case, when the tubing
210 is positioned inside of the tubing 220, a space 240 is formed
between the outer surface 214 of the tubing 210 and the inner
surface 222 of the tubing 220. The size (e.g., inner diameter,
outer diameter) of the tubing 210 can be substantially the same as,
or different than, the size of the tubing 215.
[0031] The multiple connection bushing 230 is a device that has a
number (e.g., three) of coupling features that allow the multiple
connection bushing 230 to mechanically couple to multiple sizes of
tubing (e.g., tubing 210, tubing 215, tubing 220) at one time. For
example, the multiple connection bushing 230 can include a bottom
coupling feature 233 that mechanically couples to the proximal end
of the tubing 215. As another example, the multiple connection
bushing 230 can include a top coupling feature 231 that
mechanically couples to the distal end of the tubing 210. As still
another example, the multiple connection bushing 230 can include
another top coupling feature 232 that mechanically couples to the
distal end of the tubing 220.
[0032] Each coupling feature of the multiple connection bushing 230
can be any type of coupling feature that complements the coupling
feature of the respective tubing to which the multiple connection
bushing 230 attaches. Examples of such coupling features can
include, but are not limited to, mating threads, slots, and
compression fittings. The multiple connection bushing 230 can
include an inner surface 234 and an outer surface 236 and have a
generally cylindrical shape. The inner surface 234 can form a
passage 218 that traverses the length of the multiple connection
bushing 230. The multiple connection bushing 230 can be made of one
or more of a number of suitable materials, including but not
limited to steel. In such a case, when a tubing is mechanically
coupled to the multiple connection bushing 230, the tubing and the
multiple connection bushing 230 form a tight seal that is
substantially impervious to the passage of fluids or gases.
[0033] In certain example embodiments, one or more of a number of
centralizers 250 are disposed between the tubing 210 and the tubing
220. Each centralizer 250 can be tubular in shape (wrapping around
tubing 210), segmented, or have any of a number of other shapes
and/or configurations. Each centralizer 250 can have one or more
features (e.g., slots that traverse its height, a lattice
structure) that allow air to flow therethrough. As such, when a
centralizer is positioned in the space 240 between the tubing 210
and the tubing 220, there is no pressure differential between one
side of the centralizer 250 and the other side of the centralizer
250.
[0034] The centralizer can be made of one or more of a number of
thermally non-conductive materials, including but not limited to
ceramic, plastic, and rubber. In certain example embodiments, each
centralizer 250 is used to provide physical separation between the
tubing 210 and the tubing 220. The centralizer 250 can be rigid or
somewhat elastic. The width of a centralizer 250 can be
substantially the same as, or less than, the width (e.g., one inch,
one-half inch) of the space 240 between the tubing 210 and the
tubing 220.
[0035] The space 240, formed between the tubing 210, the tubing
220, and the multiple connection bushing 250, is enclosed at or
near the surface 102 by the spacer wellhead spool 280 and the
vacuum system 285. The spacer wellhead spool 280 (also called a
spacer wellhead bowl 280) is used to secure (in this case, seal)
the upper end of the space between the tubing 210 and the tubing
220. The size and pressure rating of the spacer wellhead spool 280
can vary based on one or more of a number of factors, including but
not limited to the size of the tubing 210, the size of the tubing
220, and the minimum and/or maximum pressure in the space 240
created by the vacuum system 285.
[0036] The vacuum system 285 can include one or more components
that are used to adjust a pressure within the space 240. For
example, as shown in FIG. 2, the vacuum system 285 can include a
vacuum pump 283, piping 282, and an access valve 284, all of which
can be used to create a vacuum in the space 240 by reducing the
pressure in the space 240 toward zero (e.g., zero Torr). In
addition, or in the alternative, the vacuum system 285 can act in
reverse and increase the pressure within the space 240. In this
case, the access valve 284 is mechanically coupled to the spacer
wellhead spool 280 and provides access to the space 240 by the rest
of the vacuum system 285. In other words, the access valve 284
allows the vacuum system 285 to be communicably coupled to the
space 240.
[0037] The vacuum system 285 can be fixedly or removably coupled to
the access valve 284. If some or all of the vacuum system 285 is
removably coupled to the access valve 284, the access valve 284 can
substantially maintain the pressure (or lack thereof) in the space
240 for a period of time (e.g., days, months) after such components
of the vacuum system 285 are removed and no longer coupled to the
access valve 284. The vacuum pump 283 can include a motor, a pump,
and/or any other equipment to enable the vacuum pump 283 to create
a vacuum in the space 240. The vacuum pump 283 and the piping 282
can be sized and/or configured in a manner consistent with the
operating parameters of the system 200.
[0038] In certain example embodiments, one or more components
(e.g., a motor, a motorized valve) of the vacuum system 285 can
operate using electricity. Such components of the vacuum system 285
can run, at least in part, using electric power fed from, for
example, one or more cables 299. For example, the power source 203
can be electrically coupled to the vacuum system 285 using the
cable 299. The power source 203 can deliver a constant or a
variable amount of power to the vacuum system 285.
[0039] In addition, or in the alternative, the power cables 299 can
provide power generated by the power source 203 to one or more
other components of the system 200. The power source 203 can be any
device (e.g., generator, battery) capable of generating electric
power. Other components of the system 200 that can operate using
electric power generated by the power source 203 can include, but
are limited to, completion equipment 297 and an injection device
207, each described below. In certain example embodiments, the
power source 203 is electrically coupled to one or more cables 299.
In such a case, the cables 299 can be capable of maintaining an
electrical connection between the power source 203 and one or more
components of the system 200 when such components are
operating.
[0040] The power generated by the power source 203 can be
alternating current (AC) power or direct current (DC) power. If the
power generated by the power source 203 is AC power, the power can
be delivered in a single phase. The power generated by the power
source 203 can be conditioned (e.g., transformed, inverted,
converted) by a power conditioner (not shown) before being
delivered to the component using a cable 299.
[0041] In certain example embodiments, completion equipment 297 can
be disposed within the cavity 208. In some cases, the completion
equipment 297 is located below the first tubing 215 in the wellbore
120. The completion equipment 297 of FIG. 2 can include one or more
of a number of components, including but not limited to a power
conditioner, a motor, a pump, and a valve. For example, the
completion equipment 297 can be a pump assembly (e.g., pump, pump
motor) that can pump, when operating, oil, gas, and/or other
production fluids from the wellbore 120 through the distal end of
the tubing 215 and up the annulus 217 of the tubing 215, through
the passage 218 of the multiple connection bushing, and up the
annulus 216 of the tubing 210 to the surface 102.
[0042] One or more components of the completion equipment 297 can
operate using electric power. In such a case, the completion
equipment 297 can receive power from the power source 203 using a
cable 299 that is run in the cavity 208 between the casing 260 and
the outer surface 224 of the tubing 220. The power received by the
completion equipment 297 can be the same type of power (e.g., AC
power, DC power) generated by the power source 203. The power
received by the completion equipment 297 can be conditioned (e.g.,
transformed, inverted, converted) into any level and/or form
required by the completion equipment 297. In some cases, the
completion equipment 297 can include a control system that controls
the functionality of the completion equipment 297. Such a control
system can be communicably coupled with a user and/or some other
system so that the control system can receive and/or send commands
and/or data.
[0043] In certain example embodiments, the cavity 208 is physically
and/or thermally separated from the area in the wellbore 120 where
the perforations are located so that the cavity 208 does not
experience the same operating conditions as the area where the
perforations are located. For example, one or more packers (not
shown) can be installed (for example, between the tubing 215 and
the casing 260 and/or wall of the wellbore 120. In such a case, the
packers can have passages that traverse therethrough and allow one
or more devices such as cables 299 to traverse the packers. In the
case of cables 299, the cables 299 can traverse the packers to
electrically couple to the completion equipment 297 located toward
the bottom of the wellbore 120 (or, at least, below the
packers).
[0044] In certain example embodiments, the lower wellhead spool 270
(also called the lower wellhead bowl 270) and the upper wellhead
spool 290 (also called the upper wellhead bowl 290) are similar to
the spacer wellhead spool 280. In this case, the lower wellhead
spool 270 can be used to secure the upper end of the casing 260
and/or the tubing 220. In addition, the upper wellhead spool 290
can be used to secure the upper end of the tubing 210. The size and
pressure rating of the lower wellhead spool 270 and the upper
wellhead spool 290 can vary based one or more of a number of
factors, including but not limited to the weight of the tubing 210,
the weight of the tubing 220, and the weight of the casing 260.
[0045] The optional Christmas tree 295 is an assembly of devices
such as valves, spools, pressure gauges, and chokes that are fitted
to the wellhead and are used to control extraction of the
production fluid. The Christmas tree 295 can be located at or near
the surface 102. The Christmas tree 295 can include, or be separate
from, the injection device 207. If one or more devices of the
Christmas tree 295 require electrical power to operate, then the
power source 203 can be electrically coupled to the Christmas tree
295.
[0046] The injection device 207 can be separate from or part of the
Christmas tree 295 and can be used to send the working fluid into
the wellbore through the cavity formed by the annulus 216 of the
tubing 210, the passage 218 through the multiple connection bushing
230, and the annulus 218 of the tubing 215. The injection device
207 can be located at or near the surface 102. The injection device
207 can be communicably coupled to the cavity formed by the annulus
216 of the tubing 210, the passage 218 through the multiple
connection bushing 230, and the annulus 217 of the tubing 215.
[0047] In certain example embodiments, the injection device 207 can
also process (e.g., pressurize, heat) the working fluid before the
working fluid is injected into the wellbore 120. The processing and
injection of the working fluid can occur using the same or
different devices. To the extent that one or more components of the
injection device 207 requires electrical power to operate, then the
power source 203 can be electrically coupled to the injection
device 207 using one or more cables 299.
[0048] FIG. 3 shows a schematic diagram of another system 300 for
vacuum-insulated tubing in a wellbore in accordance with certain
example embodiments. In one or more embodiments, one or more of the
features shown in FIG. 3 may be omitted, added, repeated, and/or
substituted. Accordingly, embodiments of a system for
vacuum-insulated tubing in a wellbore should not be considered
limited to the specific arrangements of components shown in FIG.
3.
[0049] The components of the system 300 of FIG. 3 are substantially
the same as the components of the system 200 of FIG. 2, as
described above, with the exceptions noted below. For example, the
lower wellhead spool 370, the tubing 310, the tubing 320, the
casing 360, the vacuum system 385, and the spacer wellhead spool
380 of FIG. 3 are substantially the same as the lower wellhead
spool 270, the tubing 210, the tubing 220, the casing 260, the
vacuum system 285, and the spacer wellhead spool 280 of FIG. 2.
FIG. 3 includes a casing wellhead spool 365, which can be used to
secure the upper end of the casing 360 while the lower wellhead
spool 370 can be used to secure the upper end of the tubing
220.
[0050] In place of the upper wellhead spool 290 shown in FIG. 2,
FIG. 3 includes a riser 305 that includes a riser housing 308 and a
riser joint 375. The riser housing 308 can be positioned atop the
spacer wellhead spool 380 above the surface 102. The riser housing
308 can include a cavity 307 that is filled with a lubricant 387
(e.g., oil, grease). The riser housing 308 can also include at
least one sealing member that keeps most of the lubricant 387 in
the cavity 307 as the riser joint 375 moves up and down within a
channel (hidden from view by the riser joint 375) that traverses
the riser housing 308. In this example, a sealing member 304 is
disposed within the top wall of the riser housing 308 and is
located between the riser housing 308 and the riser joint 375. In
addition, as shown in FIG. 3, a sealing member 303 is disposed
within the bottom wall of the riser housing 308 and is located
between the riser housing 308 and the riser joint 375.
[0051] In certain example embodiments, the riser joint 375 is
mechanically coupled to the proximal end of the tubing 310. Since
the riser joint 375 is able to move up and down within the channel
that traverses the riser housing 308, the tubing 310 can freely
expand and contract as its temperature rises and falls, coinciding
with when the working fluid is injected into the wellbore 120 and
when the production fluid is extracted from the wellbore 120.
[0052] The vacuum created in the space 340 acts as a tremendous
insulator. Thus, the vacuum created in the space 340 can cause
significant temperature differences between the tubing 310 and the
tubing 320 as the working fluid is injected into the wellbore 120
through the cavity formed, in part, by the annulus of the tubing
310. For example, as working fluid is injected into the wellbore
120, the temperature of the tubing 310 can be approximately
750.degree. F., while the temperature of the tubing 320 can be
approximately 150.degree. F. In such a case, the temperature of the
working fluid can exceed 750.degree. F.
[0053] As a result of the temperature differences between the
tubing 310 and the tubing 320, the higher temperature tubing 310
can expand more than the relatively lower temperature tubing 320.
The relative expansion of the tubing 310 compared to the tubing 320
can depend on one or more of a number of factors, including but not
limited to the temperature of the working fluid, the depth of the
wellbore 120, and the material used for the tubing 310 and the
tubing 320. In a number of cases, as an example, the thermal
expansion of the tubing 310 can be over 25 feet, while the thermal
expansion of the tubing 320 can be only a couple of feet.
[0054] The riser 305 allows for this differential in expansion
between the tubing 310 and the tubing 320. Specifically, as the
tubing 310 expands at a faster rate than the tubing 320, the riser
joint 375 elevates without compromising the vacuum formed in the
space 340 between the tubing 310 and the tubing 320. Thus, the
tubing 310 can receive uniform thermal distribution and so have
more efficient transfer of the heat to the production fluid in the
wellbore 120. The riser 305 also allows for a higher temperature
differential between the tubing 310 and the tubing 320 without
deforming or destroying a spool, compromising the vacuum, and/or
causing any other problems in the system 300.
[0055] FIG. 4 is a flowchart presenting a method 400 for creating
vacuum-insulated tubing in a wellbore in accordance with certain
example embodiments. FIG. 5 is a flowchart presenting a method for
extracting a downhole fluid in a wellbore using vacuum-insulated
tubing in accordance with certain example embodiments. While the
various steps in these flowcharts are presented and described
sequentially, one of ordinary skill will appreciate that some or
all of the steps may be executed in different orders, may be
combined or omitted, and some or all of the steps may be executed
in parallel. Further, in one or more of the example embodiments,
one or more of the steps described below may be omitted, repeated,
and/or performed in a different order. In addition, a person of
ordinary skill in the art will appreciate that additional steps not
shown in FIGS. 4 and 5, may be included in performing this method.
Accordingly, the specific arrangement of steps should not be
construed as limiting the scope.
[0056] Referring now to FIGS. 1, 2, 3, and 4, the example method
400 begins at the START step and proceeds to step 402, where tubing
215 is inserted into the wellbore 120. In certain example
embodiments, the tubing 215 is a number of tubing members (or
tubing pipes or tubing pipe members) that are mechanically coupled
to each other on an end-to-end basis. The amount of tubing 215 that
is inserted into the wellbore 120 can depend on one or more of a
number of factors, including but not limited to the size of the
reservoir, the inclination of the wellbore 120, and the size of the
wellbore where the reservoir is located in the wellbore 120. The
tubing 215 can be inserted into the wellbore 120 using field
equipment 130, such as, for example, a top drive and a rotary
table.
[0057] In step 404, a bottom coupling feature 233 of a multiple
connection bushing 230 is mechanically coupled to the tubing 215.
In certain example embodiments, the bottom coupling feature 233 of
the multiple connection bushing 230 is mechanically coupled to the
tubing 215 using field equipment 130, such as, for example, tongs,
a clamping device, and a rotary table. The bottom coupling feature
233 of the multiple connection bushing 230 can be mechanically
coupled to the tubing 215 at or above the surface 102.
[0058] In step 406, tubing 210 is mechanically coupled to a first
top coupling feature 231 of the multiple connection bushing 230. In
certain example embodiments, the tubing 210 is mechanically coupled
to the first top coupling feature 231 of the multiple connection
bushing 230 using field equipment 130, such as, for example, tongs,
a clamping device, and a rotary table. The tubing 210 can be
mechanically coupled to the first top coupling feature 231 of the
multiple connection bushing 230 at or above the surface 102. In
certain example embodiments, the tubing 210 is a number of tubing
members that are mechanically coupled to each other on an
end-to-end basis.
[0059] In step 408, tubing 220 is mechanically coupled to a second
top coupling feature 232 of the multiple connection bushing 230. In
certain example embodiments, the tubing 220 is mechanically coupled
to the second top coupling feature 232 of the multiple connection
bushing 230 using field equipment 130, such as, for example, tongs,
a clamping device, and a rotary table. The tubing 220 can be
mechanically coupled to the second top coupling feature 232 of the
multiple connection bushing 230 at or above the surface 102. In
some cases, after performing step 406, but prior to or while
performing step 408, one or more centralizers 250 are positioned
around an outer surface of the tubing 210.
[0060] In certain example embodiments, the tubing 220 has an inner
diameter that is greater than an outer diameter of the tubing 210.
In addition, or in the alternative, the tubing 220 can have an
outer diameter that is less than an inner diameter of production
tubing 260 inserted into the wellbore 120. In certain example
embodiments, the tubing 220 is a number of tubing members that are
mechanically coupled to each other on an end-to-end basis. The
length of each tubing member of the tubing 220 can be the same or a
different length of each tubing member of the tubing 210. When the
tubing 210 and the tubing 220 are each a number of tubing members,
the length of each of the tubing members can be the same or
different than each other.
[0061] In step 410, the multiple connection bushing 230, the tubing
210, and the tubing 220 are inserted into the wellbore 120. The
multiple connection bushing 230, the tubing 210, and the tubing 220
can be inserted into the wellbore 120 using field equipment 130,
such as, for example, a top drive and a rotary table. When the
tubing 210 and the tubing 220 are each a number of tubing members,
one tubing member or a stand (e.g., three pre-connected) of tubing
members of tubing 210 and tubing 220 can be mechanically coupled to
the multiple connection bushing 230 before the multiple connection
bushing 230, the tubing 210, and the tubing 220 are inserted into
the wellbore 120. Subsequently, one or more additional tubing
members or stands of tubing members of tubing 210 and tubing 220
can be mechanically coupled to the previously coupled portions of
the tubing 210 and the tubing 220 that have been, at least
partially, inserted into the wellbore 120.
[0062] In step 412, pressure is adjusted within the space 240
between the multiple connection bushing 230, the tubing 210, and
the tubing 220. In certain example embodiments, the pressure within
the space 240 is adjusted using a vacuum system 285 that is
communicably coupled to a spacer wellhead spool 280. In such a
case, the vacuum system 385 adjusts the pressure in the space 240
by removing pressure from the space 240. One or more components of
the vacuum system 285 (e.g., the vacuum pump 283) can operate on
electric power generated by a power source 203 that is electrically
coupled to the vacuum system 285 using one or more cables 299.
Alternatively, the vacuum system 385 can include one or more
components (e.g., an air compressor) that allow the vacuum system
385 to adjust the pressure in the space 240 by increasing the
pressure within the space 240. Once step 412 is completed, the
process ends with the END step.
[0063] As discussed above with respect to FIG. 3, as a result of
the vacuum created in the space 340 between the tubing 310 and the
tubing 320, the tubing 310 can be subject to significantly higher
temperatures than the tubing 320. Thus, in certain example
embodiments, the tubing 310 can be allowed to expand and contract
with temperature independent of the expansion and contraction of
the tubing 320. Allowing the independent expansion and contraction
of the tubing 310 relative to the tubing 320 can be achieved using,
for example, the riser 305 that includes the riser housing 308 and
the riser joint 375, where the riser joint is mechanically coupled
to the top end of the tubing 310. In such a case, the space 340 can
remain depressurized (or, in the alternative, pressurized) when the
tubing 310 expands and contracts.
[0064] In addition to higher temperatures, the tubing 210 can also
be subject to higher pressures than the tubing 220. Such pressures
in the annulus 216 of the tubing 210 can be based on the injection
pressure of the working fluid. For example, when the working fluid
is injected through the annulus 216 of the tubing 210, the annulus
216 can be subjected to any of a number (e.g., 3,300 psi) of
constant or variable pressures that substantially equal the
injection pressure, as created by the injection device 207, of the
working fluid. The amount of pressure in the annulus 216 of the
tubing 210(and so also the injection pressure) can be controlled
through the injection device 207 by a user, by an automated control
system, and/or by some other means. In addition, the pressure
within the space 340 can be substantially uniformly along its
length. As a result, the temperature of the tubing 320 can be
substantially equal along its length and substantially lower than
the temperature of the tubing 310, which greatly reduces the risk
of damaging the casing 360 and/or the wellbore 120.
[0065] By performing the method 400 of FIG. 4, the vacuum-insulated
tubing in the wellbore 120 can be used in one or more of a number
of applications that requires isolating temperatures and/or
creating a radial and/or horizontal temperature differential within
a wellbore 120. One such application is described below in FIG. 5,
which shows a flowchart presenting a method 500 for extracting a
downhole fluid in a wellbore using vacuum-insulated tubing in
accordance with certain example embodiments. Those skilled in the
art will appreciate that other applications associated with a field
operation can be enhanced and/or performed using example
vacuum-insulated tubing. Referring now to FIGS. 1, 2, 3, 4, and 5,
the example method 500 begins at the START step and proceeds to
step 502. Steps 502-512 of the method 500 of FIG. 5 are
substantially similar to steps 402-412 of the method 400 of FIG.
5.
[0066] Once step 512 is complete, the method 500 continues to step
514, where a working fluid is inserted into the cavity formed by
the annulus 216 of the tubing 210, the passage 218 through the
multiple connection bushing 230, and the annulus 217 of the tubing
215. In certain example embodiments, the working fluid is inserted
into the cavity by the injection device 207. The injection device
207 can inject a fixed or variable amount of working fluid that is
regulated at a fixed or variable temperature. The injection device
207 can be controlled by a user, by a control system, and/or by
some other means. In certain example embodiments, the temperature
of the working fluid exceeds 750.degree. F.
[0067] In step 516, production fluid is extracted from the wellbore
120 after the working fluid interacts with the production fluid in
the wellbore 120. In certain example embodiments, the production
fluid is extracted using completion equipment 297. As explained
above, the tubing 210 can have a temperature that is substantially
higher than the temperature of the tubing 220 when the working
fluid is inserted into the cavity (and, more specifically, into the
annulus 216 of the tubing 210). Once step 516 is completed, the
process ends with the END step. Alternatively, when step 516 is
completed, the method 500 can repeat one or more times by reverting
to step 514.
[0068] The systems, methods, and apparatuses described herein allow
for creating a vacuum (or adding pressure) within a portion of a
wellbore using existing tubing. Example embodiments significantly
reduce cost over currently used systems that include specially-made
vacuum tubing. Further, example embodiments provide a vacuum that
is continuous, rather than segmented when using currently available
technology. As a result, the temperature of the components (e.g.,
casing) close to the wall of the wellbore (away from the radial
center of the wellbore) are lower using example embodiments
compared to using existing technology. Thus, there is a lower
likelihood that high temperatures will compromise the wellbore
where the working fluid passes.
[0069] In addition, using example embodiments, the inner-most
tubing (i.e., the tubing through which the high-temperature working
fluid is injected) can freely expand and contract, independent of
the expansion and contraction of the outer tubing through which the
inner-most tubing traverses. As a result, the working fluid can be
injected into the wellbore at higher temperatures using example
embodiments than it can using current technology. Thus, the
viscosity of the production fluid can be further enhanced using
example embodiments, making extraction of the production fluid
easier and more cost-effective.
[0070] In addition to heating production fluid, the systems and
methods described herein can be used in a number of other downhole
applications. Specifically, the higher range of temperatures of the
working fluid, the contiguousness of the vacuum, and/or the
independent movement of the various components of the system can be
used for one or more of a number of downhole applications within a
wellbore. For example, systems and methods described herein can be
used to cause a chemical reaction.
[0071] Although embodiments described herein are made with
reference to example embodiments, it should be appreciated by those
skilled in the art that various modifications are well within the
scope and spirit of this disclosure. Those skilled in the art will
appreciate that the example embodiments described herein are not
limited to any specifically discussed application and that the
embodiments described herein are illustrative and not restrictive.
From the description of the example embodiments, equivalents of the
elements shown therein will suggest themselves to those skilled in
the art, and ways of constructing other embodiments using the
present disclosure will suggest themselves to practitioners of the
art. Therefore, the scope of the example embodiments is not limited
herein.
* * * * *